UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022
12/31
OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___  to  ___.

Commission file number:  1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as Specified in Its Charter)

Delaware
 
76-0568219
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
 
1100 Louisiana Street, 10th Floor, Houston, Texas 77002
    (Address of Principal Executive Offices, including Zip Code)
(713) 381-6500
(Registrant’s Telephone Number, including Area Code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of Each Class
Trading Symbol(s)
Name of Each Exchange On Which Registered
Common Units
EPD
New York Stock Exchange

Securities to be registered pursuant to Section 12(g) of the Act:  None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes    No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes    No 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes   No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer Accelerated filer     Non-accelerated filer       Smaller reporting company      Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. 

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. 

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes     No

The aggregate market value of our common units held by non-affiliates at June 30, 2022 (the last business day of the registrant’s most recently completed second fiscal quarter) was $35.99 billion based on a closing price on that date of $24.13 per common unit on the New York Stock Exchange Composite ticker tape.  There were 2,170,806,347 common units outstanding at January 31, 2023.





ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

   
Page
   
Number
     
     
     
     
 











CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION


This annual report on Form 10-K for the year ended December 31, 2022 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this annual report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  

Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this annual report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.














KEY REFERENCES USED IN THIS REPORT

Unless the context requires otherwise, references to “we,” “us” or “our” within this annual report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  

References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business.  We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP;  (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.  The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are:  (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO.  Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees.  EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at December 31, 2022.

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

/d
=
per day
MMBPD
=
million barrels per day
BBtus
=
billion British thermal units
MMBtus
=
million British thermal units
Bcf
=
billion cubic feet
MMcf
=
million cubic feet
BPD
=
barrels per day
MWac
=
megawatts, alternating current
MBPD
=
thousand barrels per day
MWdc
=
megawatts, direct current
MMBbls
=
million barrels
TBtus
=
trillion British thermal units













PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”  Our preferred units are not publicly traded.  We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products.  We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership.  We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets.  Our midstream energy operations include:

natural gas gathering, treating, processing, transportation and storage;

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);

crude oil gathering, transportation, storage, and marine terminals;

propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 

Our business strategy seeks to manage these operations to:

capitalize on expected trends and opportunities in all energy supply and demand cycles to provide value added services to our customers;

maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary assets that enhance our overall value chain; and

share capital costs and risks through business ventures or alliances with strategic partners, including those that provide incremental volumes on our systems.

Our financial position, results of operations and cash flows are contingent on the supply of, and demand for the energy commodities we handle across our integrated midstream energy asset network.  See “Current Outlook” included under Part II, Item 7 of this annual report for management’s views on key midstream energy supply and demand fundamentals in 2023.




Business Segments

The following sections provide an overview of our business segments, including information regarding principal products produced and/or services rendered and properties owned.  Our operations are reported under four business segments:  NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services.

Each of our business segments benefits from the supporting role of our marketing activities.  The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of segment gross operating margin for us.  The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “Risk Factors” included under Part I, Item 1A of this annual report.  In addition, our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters.  For a discussion of the principal effects of such laws and regulations on our business activities, see “Regulatory Matters” within this Part I, Items 1 and 2 discussion.

For management’s discussion and analysis of our results of operations, liquidity and capital resources and capital investment program, see Part II, Item 7 of this annual report.

For detailed financial information regarding our business segments, including major customer information, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

NGL Pipelines & Services

This business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

Natural gas processing and related NGL marketing activities
At the core of our natural gas processing business are processing facilities located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.

In its raw form, natural gas produced at the wellhead (especially in association with crude oil production) contains varying amounts of NGLs such as ethane and propane.  Natural gas streams containing NGLs and other impurities are usually not acceptable for transportation in downstream natural gas transmission pipelines or for commercial use as fuel; therefore, the unprocessed natural gas stream must be transported to a natural gas processing facility to remove the NGLs and other impurities. Once the natural gas is processed and the NGLs and impurities are removed, the residue natural gas meets downstream natural gas pipeline and commercial quality specifications.

In general, on an energy-equivalent basis, NGLs have greater economic value as feedstock for petrochemical and motor gasoline production than as components of a natural gas stream. Typical uses of NGLs include the following:

Ethane is primarily used in the petrochemical industry as a feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

Propane is used for heating, as an engine and industrial fuel, and as a petrochemical feedstock in the production of ethylene and propylene.

Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline, and to produce isobutane through isomerization.

Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, and is used in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives, and in the production of propylene oxide.

Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline, diluent in crude oil to aid in transportation, and as a petrochemical feedstock.

The results of operations from natural gas processing are primarily dependent on the difference between the revenues we earn from extracting NGLs (in terms of cash processing fees and/or the value of any retained NGLs) and the cost of natural gas and other operating costs incurred in connection with such extraction activities.

Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms.  To the extent we retain all or a portion of the extracted NGLs as consideration for our processing services, we refer to such volumes as our “equity NGL-equivalent production.”

If the operating costs of a natural gas processing facility are higher than the incremental value of the NGLs that would be extracted, then recovery levels of certain NGLs, primarily ethane, may be purposefully reduced. This scenario is typically referred to as “ethane rejection” and results in a reduction in NGL volumes available to us for subsequent transportation, fractionation, storage and marketing.

Our NGL marketing activities entail spot and term sales of NGLs that we take title to through our natural gas processing activities (i.e., our equity NGL-equivalent production) and open market and contract purchases. The results of operations for NGL marketing are primarily dependent on the difference between NGL sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets by the marketing group.  Market prices for NGLs are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control.  We attempt to mitigate these price risks through the use of commodity derivative instruments.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

The following table presents selected information regarding our natural gas processing facilities at February 1, 2023:

       
Total Gas
       
Net Gas
Processing
   
Production
 
Processing
Capacity
   
Region
Ownership
Capacity
of Plant
Facility Name
Location(s)
Served
Interest
(MMcf/d) (1)
(MMcf/d)
South Texas (2)
Texas
Eagle Ford, Strawn
100.0%
2,200
2,200
Meeker
Colorado
Piceance
100.0%
 1,800
 1,800
Delaware Basin (3)
Texas, New Mexico
Delaware
100.0%
1,595
1,595
Midland Basin (4)
Texas
Midland
100.0%
1,020
1,020
Pioneer
Wyoming
Green River
100.0%
 800
 800
Pascagoula
Mississippi
Gulf of Mexico
  75.0%   (5)
750
 1,000
Chaco
New Mexico
San Juan
100.0%
 600
 600
Neptune
Louisiana
Gulf of Mexico
  66.0%   (6)
 429
 650
Carthage (7)
Texas
Cotton Valley
100.0%
320
320
Venice
Louisiana
Gulf of Mexico
  13.1%   (8)
 98
 750
Indian Springs
Texas
Wilcox-Woodbine
  75.0%   (6)
 90
 120
    Total
     
9,702
10,855

(1)
The approximate net gas processing capacity does not necessarily correspond to our ownership interest in each facility.  The capacity is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners.
(2)
The South Texas processing facility consists of eight natural gas processing plants: Yoakum I, Yoakum II, Yoakum III, Thompsonville, Shoup, Armstrong, San Martin and Sonora.
(3)
The Delaware Basin processing facility consists of seven natural gas processing plants: Orla I, Orla II, Orla III, Mentone I, South Eddy, Waha and Chaparral.
(4)
The Midland Basin processing facility consists of five natural gas processing plants: Newberry I, Newberry II, Leiker, Trident and Taylor.
(5)
We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC.
(6)
We proportionately consolidate our undivided interests in these operating assets.
(7)
The Carthage processing facility consists of two natural gas processing plants: Panola and Bulldog.
(8)
Our 13.1% ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C.


We operate all of our natural gas processing facilities except for the Venice plant.  On a weighted-average basis, utilization rates for our natural gas processing facilities were approximately 66.5%, 58.1% and 57.6% during the years ended December 31, 2022, 2021 and 2020, respectively.

Midland Basin natural gas processing facility.  The Midland Basin natural gas processing facility consists of five natural gas processing plants, which includes four natural gas processing plants (Newberry I, Newberry II, Trident and Taylor) that we acquired as part of our acquisition of Navitas Midstream Partners, LLC (“Navitas Midstream”) in February 2022 and a fifth natural gas processing plant (Leiker), which we completed construction of and placed into service in March 2022.  See Part II, Item 7 of this annual report for additional information regarding our acquisition of Navitas Midstream.

During 2022, we announced plans to construct two new natural gas processing plants in the Midland Basin, Poseidon (previously referred to as Plant 6) and Leonidas (previously referred to as Plant 7), which are expected to be placed into service in the third quarter of 2023 and first quarter of 2024, respectively.  Each of these plants will have the capacity to process 300 MMcf/d of natural gas and extract over 40 MBPD of NGLs and are supported by long-term acreage dedication agreements.

Once the Poseidon and Leonidas plants are completed and placed into service, we expect to have an aggregate 1.6 Bcf/d of natural gas processing capacity and more than 220 MBPD of NGL production capacity from our natural gas processing facility in the Midland Basin.

Delaware Basin natural gas processing facility.  During 2022, we announced plans to construct two additional natural gas processing plants in the Delaware Basin, the Mentone II and III plants, which are expected to be placed into service in the fourth quarter of 2023 and first quarter of 2024, respectively.  Each of these plants will have the capacity to process 300 MMcf/d of natural gas and extract 40 MBPD of NGLs and are supported by long-term capacity agreements.

When the Mentone II and III plants are completed and placed into service, we expect to have an aggregate 2.2 Bcf/d of natural gas processing capacity and more than 300 MBPD of NGL production capacity from our natural gas processing facility in the Delaware Basin.

Our NGL marketing activities utilize a fleet of approximately 480 railcars, the majority of which are leased from third parties.  These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the U.S. and parts of Canada.  We have rail loading and unloading capabilities at certain of our terminal facilities in Arizona, Kansas, Louisiana, Minnesota, Mississippi, New York, North Carolina and Texas. These facilities service both our rail shipments and those of our customers. Our NGL marketing activities also utilize a fleet of approximately 180 tractor-trailer tank trucks that are used to transport LPG for us and on behalf of third parties.  We lease and operate the majority of these trucks and trailers.

NGL pipelines
Our NGL pipelines transport mixed NGLs from natural gas processing facilities, refineries and marine terminals to downstream fractionation plants and storage facilities; gather and distribute purity NGL products to and from fractionation plants, storage and terminal facilities, petrochemical plants, refineries and export facilities; and deliver propane and ethane to destinations along our pipeline systems.

The results of operations from our NGL pipelines are primarily dependent upon the volume of NGLs transported (or capacity reserved) and the associated fees we charge for such transportation services. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”), or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental regulation of our liquids pipelines.


The following table presents selected information regarding our NGL pipelines at February 1, 2023:

   
Pipeline
   
Ownership
Length
Description of Asset
Location(s)
Interest
(Miles)
Mid-America Pipeline System (1)
Midwest and Western U.S.
 100.0%
7,862
South Texas NGL Pipeline System
Texas
 100.0%
2,032
Dixie Pipeline (1)
South and Southeastern U.S.
 100.0%
1,307
ATEX (1)
Texas to Midwest and Northeast U.S.
 100.0%
1,229
Chaparral NGL System (1)
Texas, New Mexico
 100.0%
1,085
Louisiana Pipeline System (1)
Louisiana
 100.0%
875
Seminole NGL Pipeline (1)
Texas
 100.0%
869
Shin Oak NGL Pipeline
Texas
   67.0% (3)
670
Texas Express Pipeline (1)
Texas
   35.0% (4)
594
Skelly-Belvieu Pipeline (1)
Texas, Oklahoma
   50.0% (5)
572
Front Range Pipeline (1)
Colorado, Oklahoma, Texas
   33.3% (6)
 452
Houston Ship Channel Pipeline System
Texas
 100.0%
307
Panola Pipeline (1)
Texas
   55.0%  (7)
253
Rio Grande Pipeline (1)
Texas
 100.0%
249
Aegis Ethane Pipeline (1)
Texas, Louisiana
 100.0%
233
Lou-Tex NGL Pipeline (1)
Texas, Louisiana
 100.0%
206
Promix NGL Gathering System
Louisiana
   50.0%  (8)
194
Tri-States NGL Pipeline (1)
Alabama, Mississippi, Louisiana
   83.3% (9)
168
Texas Express Gathering System
Texas
   45.0% (10)
138
Others (nine systems) (2)
Various
 Various (11)
525
   Total
   
19,820

(1)
Interstate transportation services provided by these liquids pipelines, in whole or part, are regulated by federal governmental agencies.
(2)
Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana; two pipelines located near Port Arthur in southeast Texas; our San Jacinto pipeline located in East Texas; our Permian NGL lateral pipelines located in New Mexico; Leveret pipeline in West Texas and New Mexico; Enterprise Ethane Pipeline in Texas; and a pipeline in Colorado associated with our Meeker facility.  Transportation services provided by the Wilprise and Leveret pipelines are regulated by federal governmental agencies.
(3)
We own a 67% consolidated interest in the Shin Oak NGL Pipeline through our majority owned subsidiary, Breviloba, LLC.
(4)
Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC.
(5)
Our 50% ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C.
(6)
Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC.
(7)
We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC.
(8)
Our 50% ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C.
(9)
We own an 83.3% consolidated interest in the Tri-States NGL Pipeline through our majority owned subsidiary, Tri-States NGL Pipeline, L.L.C.
(10)
Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC.
(11)
We own a 74.7% consolidated interest in the 30-mile Wilprise pipeline through our majority owned subsidiary, Wilprise Pipeline Company, L.L.C.  We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines.  The remainder of these NGL pipelines are wholly owned.

The maximum number of barrels per day that our NGL pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each injection and delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our NGL pipelines in terms of net throughput, which is based on our ownership interest.  In the aggregate, net throughput volumes for these pipelines were 3,703 MBPD, 3,412 MBPD and 3,589 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

We operate our NGL pipelines with the exception of the Texas Express Gathering System. The following information describes our principal NGL pipelines:

The Mid-America Pipeline System is an NGL pipeline system consisting of the 3,119-mile Rocky Mountain pipeline, the 2,023-mile Conway North pipeline, the 632-mile Ethane-Propane (“EP”) Mix pipeline, and the 2,088-mile Conway South pipeline. The Rocky Mountain pipeline transports mixed NGLs from production fields located in the Rocky Mountain Overthrust and San Juan Basin to the Hobbs NGL hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. NGL hubs provide buyers and sellers with a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines. The EP Mix segment transports EP mix from the Conway hub to petrochemical plants in Iowa and Illinois. The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between the Conway and Hobbs hubs.  At the Hobbs NGL hub, the Mid-America Pipeline System interconnects with our Seminole NGL Pipeline and Hobbs NGL fractionation and storage facility. The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals that we own and operate.

The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas that gather and transport mixed NGLs from natural gas processing facilities (owned by either us or third parties) to our NGL fractionators located in South Texas and in Chambers County, Texas. In addition, this system transports purity NGL products from our South Texas NGL fractionators to refineries and petrochemical plants located between Corpus Christi, Texas and Houston, Texas and within the Texas City-Houston area, as well as to interconnects with other NGL pipelines and to our Chambers County storage complex.  The South Texas NGL Pipeline System extends our ethane header system from Chambers County, Texas to Corpus Christi, Texas.

The Dixie Pipeline transports propane and other NGLs from locations in southeast Texas, south Louisiana and Mississippi to markets in the southeastern U.S.  The Dixie Pipeline operates in seven states:  Alabama, Georgia, Louisiana, Mississippi, North Carolina, South Carolina and Texas, and is connected to eight non-regulated propane terminals that we own and operate.

The Appalachia-to-Texas Express, or ATEX, pipeline transports ethane in southbound service from third-party owned NGL fractionation plants located in Ohio, Pennsylvania and West Virginia to our Chambers County storage complex.  Ethane originating at these fractionation facilities is sourced from the Marcellus and Utica Shale production areas. ATEX operates in nine states: Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia.

The Chaparral NGL System transports mixed NGLs from natural gas processing facilities located in West Texas and New Mexico to Chambers County, Texas.  This system consists of the 906-mile Chaparral pipeline and the 179-mile Quanah pipeline. Interstate and intrastate transportation services provided by the Chaparral pipeline are regulated; however, transportation services provided by the Quanah pipeline are not.

The Louisiana Pipeline System is a network of NGL pipelines that transport NGLs originating in Louisiana and Texas to refineries and petrochemical plants located along the Mississippi River corridor in southern Louisiana.  This system also provides transportation services for our natural gas processing facilities, NGL fractionators and other assets located in Louisiana.

The Seminole NGL Pipeline transports NGLs from the Hobbs hub and the Permian Basin to markets in southeast Texas, including our Chambers County NGL fractionation complex.  NGLs originating on the Mid-America Pipeline System are a significant source of throughput for the Seminole NGL Pipeline.

The Shin Oak NGL Pipeline transports NGL production from Orla, Texas in the Permian Basin to our Chambers County NGL fractionation and storage complex.

In August 2022, we announced plans to expand our Shin Oak NGL Pipeline transportation capacity by up to 275 MBPD to approximately 825 MBPD.  We anticipate that this expansion project will be completed in the first half of 2025.

The Texas Express Pipeline extends from Skellytown, Texas to our Chambers County NGL fractionation and storage complex.  Mixed NGLs from production fields located in the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown.  In addition, the Texas Express Pipeline transports mixed NGLs gathered by the Texas Express Gathering System.  Also, mixed NGLs originating from the Denver-Julesburg (“DJ”) Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.

The Skelly-Belvieu Pipeline transports mixed NGLs from Skellytown, Texas to Chambers County, Texas.  The Skelly-Belvieu Pipeline receives a significant quantity of NGLs through an interconnect with our Mid-America Pipeline System at Skellytown.

The Front Range Pipeline transports mixed NGLs from natural gas processing facilities located in the DJ Basin in Colorado to an interconnect with our Texas Express Pipeline, Mid-America Pipeline System and other third-party facilities located at Skellytown, Texas.

The Houston Ship Channel Pipeline System connects our Chambers County, Texas assets to our marine terminals on the Houston Ship Channel and to area petrochemical plants, refineries and other pipelines.

The Panola Pipeline transports mixed NGLs from injection points near Carthage, Texas to Chambers County, Texas and supports the Haynesville and Cotton Valley crude oil and natural gas production areas.

The Rio Grande Pipeline transports mixed NGLs from near Odessa, Texas to a pipeline interconnect at the Mexican border south of El Paso, Texas.

The Aegis Ethane Pipeline (“Aegis”) delivers purity ethane to petrochemical facilities located along the southeast Texas and Louisiana Gulf Coast.  Aegis, when combined with our Enterprise Ethane Pipeline and a portion of our South Texas NGL Pipeline System, forms an ethane header system stretching from Corpus Christi, Texas to the Mississippi River in Louisiana.

The Lou-Tex NGL Pipeline transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets.

NGL fractionation and related facilities
Our NGL fractionators separate mixed NGLs into purity NGL products for third-party customers and our NGL marketing activities.  Mixed NGLs extracted by domestic natural gas processing facilities represent the largest source of volumes processed at our NGL fractionators.  Based upon industry data, we believe that sufficient volumes of mixed NGLs, especially those originating from natural gas processing facilities located in West Texas, will be available for fractionation for the foreseeable future.

The results of operations from our NGL fractionation business are generally dependent upon the volume of mixed NGLs fractionated and either (i) the level of fractionation fees charged (under fee-based contracts) or (ii) the value of NGLs received (under percent-of-liquids arrangements).  Under fee-based fractionation contracts, customers retain title to the NGLs that we process for them.  Under percent-of-liquids fractionation contracts, we retain a portion of the purity NGLs we separate for customers and are exposed to commodity price risk through fluctuations in NGL prices.  We attempt to mitigate these risks through the use of commodity derivative instruments.



The following table presents selected information regarding our NGL fractionation facilities at February 1, 2023:

   
Net Plant
Total Plant
   
Ownership
Capacity
Capacity
Description of Asset
Location
Interest
(MBPD) (1)
(MBPD)
NGL fractionation facilities:
       
Chambers County:
       
   Fracs I, II and III
Texas
  75.0% (2)
189
245
   Fracs IV, V, VI ,IX, X and XI
Texas
100.0%
645
645
   Fracs VII and VIII
Texas
  75.0% (3)
128
170
   Total Chambers County
   
962
1,060
Shoup and Armstrong
Texas
100.0%
93
93
Hobbs
Texas
100.0%
75
75
Norco
Louisiana
100.0%
75
75
Promix
Louisiana
  50.0%  (4)
73
145
Tebone
Louisiana
100.0%
30
30
Baton Rouge
Louisiana
  32.2%  (5)
19
60
   Total
   
1,327
1,538

(1)
The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility.  The capacity is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners.
(2)
We proportionately consolidate a 75% undivided interest in these fractionators.
(3)
We own a 75% consolidated equity interest in NGL fractionators VII and VIII through our majority owned subsidiary, Enterprise EF78 LLC.
(4)
Our 50% ownership interest in the Promix NGL fractionator is held indirectly through our equity method investment in K/D/S Promix, L.L.C.
(5)
Our 32.2% ownership interest in the Baton Rouge fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC.

On a weighted-average basis, the overall utilization rates for our NGL fractionators (based on nameplate capacities) were 100.0%, 93.8% and 101.6% during the years ended December 31, 2022, 2021 and 2020, respectively.

The following information describes our principal NGL fractionators, all of which we operate:

We own and operate NGL fractionators located in Chambers County, Texas.  These fractionators process mixed NGLs from several major NGL supply basins in North America, including the Permian Basin, Rocky Mountains, Eagle Ford Shale, Mid-Continent and San Juan Basin.  Our Chambers County NGL fractionators are connected to our network of NGL supply and distribution pipelines, approximately 130 MMBbls of underground salt dome storage capacity, along with access to international markets through our marine terminals located on the Houston Ship Channel.

In April 2022, we announced plans to construct a twelfth NGL fractionator (“Frac XII”) in Chambers County, Texas. Frac XII is expected to be capable of processing 150 MBPD of NGLs and enter service in the third quarter of 2023. Completion of this fractionator is expected to increase our total Chambers County NGL fractionation capacity to approximately 1.2 MMBPD.

The Shoup and Armstrong NGL fractionators in South Texas process mixed NGLs supplied by regional natural gas processing facilities.  Purity NGL products from these fractionators are transported to local markets in the Corpus Christi area and also to Chambers County, Texas using our South Texas NGL Pipeline System.

The Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico, Colorado and Wyoming. This fractionator receives mixed NGLs from several major supply basins, including the Mid-Continent, Permian Basin, San Juan Basin and Rocky Mountains.  The facility is located at the interconnect of our Mid-America Pipeline System and Seminole NGL Pipeline, thus providing customers access to the Conway hub and Chambers County, Texas.

The Norco NGL fractionator receives mixed NGLs from refineries and natural gas processing facilities located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Pascagoula and Venice facilities.

We also own and operate a 60 MBPD natural gasoline hydrotreater facility at our Chambers County complex along with related storage and pipeline infrastructure, which is designed to lower the sulfur content of natural gasoline.

NGL and related product storage facilities
We utilize underground salt dome storage caverns and above-ground storage tanks to store mixed and purity NGLs, petrochemicals and related products that are owned by us and our customers.  The results of operations from our storage facilities are dependent upon the level of storage capacity reserved by customers, the volume of product delivered into and withdrawn from storage, and the fees associated with each activity.

The following table presents selected information regarding our NGL and related product storage assets at February 1, 2023:

   
Net Usable
     
Storage
   
Ownership
Capacity
Description of Asset
Location
Interest
(MMBbls) (1)
Chambers County storage complex
Texas
100.0%
129.8
Almeda and Markham (2)
Texas
Leased
12.4
Breaux Bridge, Anse La Butte and Sorrento (3)
Louisiana
100.0%
11.0
Petal (4)
Mississippi
100.0%
5.4
Hutchinson (5)
Kansas
100.0%
4.0
Others (6)
Various
Various
14.4
   Total
   
177.0

(1)
Net usable storage capacity is based on our ownership interest or contractual right-of-use.
(2)
These storage facilities are used in connection with our South Texas NGL Pipeline System.
(3)
These storage facilities are used in connection with our Louisiana Pipeline System.
(4)
This storage facility is used in connection with our Dixie Pipeline.
(5)
This storage facility is used in connection with our Mid-America Pipeline System.
(6)
Primarily consists of operational storage capacity for our major pipeline systems, including the Mid-America Pipeline System, Dixie Pipeline and TE Products Pipeline.  We own substantially all of this storage capacity.

We operate substantially all of our NGL and related product storage facilities.

Our largest underground storage facility is located in Chambers County, Texas. This facility consists of 38 underground salt dome caverns used to store and redeliver mixed and purity NGLs, petrochemicals and related products.  This facility has an aggregate usable storage capacity of 129.8 MMBbls, a brine system with approximately 36 MMBbls of above-ground brine storage capacity and five wells used in brine production.

NGL marine terminals and related operations
We own and operate marine terminals (export and import) that handle NGLs. The results of operations from our NGL marine terminals, all of which are located on the Houston Ship Channel, are primarily dependent upon the level of volumes handled (loading and unloading) and the associated fees we charge for such services.

The following information describes our Houston Ship Channel terminals:

The Enterprise Hydrocarbons Terminal (“EHT”) provides terminaling services to exporters, marketers, distributors, chemical companies and major integrated oil companies.  EHT has extensive waterfront access consisting of eight deep-water ship docks and a barge dock.  The terminal can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel.  We believe that our location on the Houston Ship Channel enables us to handle larger vessels than our competitors because our waterfront has fewer draft and beam (width) restrictions.  The size and structure of our waterfront allows us to receive and unload products for our customers and provide terminaling services.

EHT can load refrigerated cargoes of low-ethane propane and/or butane (collectively referred to as LPG) onto multiple tanker vessels simultaneously.  Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays, international demand for propane as a feedstock in ethylene and propylene production, and for power generation and heating purposes.  The current estimated maximum loading capacity for LPG at EHT is approximately 835 MBPD.  EHT has the capability to load up to six Very Large Gas Carrier (“VLGC”) vessels simultaneously, while maintaining the option to switch between loading propane and butane.  EHT can load a single VLGC in less than 24 hours, creating greater efficiencies and cost savings for our customers.  LPG loading volumes at EHT averaged 555 MBPD, 501 MBPD and 588 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

The primary customer of EHT is our NGL marketing group, which uses the terminal to meet the needs of export customers.  NGL marketing transacts with these customers using long-term sales contracts with take-or-pay provisions and/or exchange agreements.  In recent years, the U.S. has become the largest exporter of LPG in the world, with shipments originating from EHT playing a key role.

EHT also includes an NGL import terminal.  This import terminal can offload NGLs from tanker vessels at rates up to 8,000 barrels per hour depending on the product.  Our NGL import volumes for the last three years were minimal.

EHT also provides terminaling services involving crude oil, propylene and refined products.  EHT’s assets and activities associated with crude oil terminaling and storage are a component of our Crude Oil Pipelines & Services business segment.  EHT’s activities involving propylene and refined products are a component of our Petrochemical & Refined Products Services business segment.

The Morgan’s Point Ethane Export Terminal, located on the Houston Ship Channel, has a nameplate loading capacity of approximately 10,000 barrels per hour of fully refrigerated ethane and is the largest of its kind in the world. The terminal supports domestic production of U.S. ethane from shale plays by providing the global petrochemical industry with access to a low-cost feedstock option and opportunities for supply diversification.  Ethane volumes handled by the terminal are sourced from our Chambers County NGL fractionation and storage complex.  Ethane loading volumes at the terminal averaged 168 MBPD, 157 MBPD and 134 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

In April 2022, we announced plans to build a new Ethane Export Terminal, which will be located in Orange County, Texas.  The project is expected to be completed in 2025.

Crude Oil Pipelines & Services

This business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.

Crude oil pipelines
We have crude oil gathering and transportation pipelines located in Oklahoma, New Mexico and Texas. The results of operations from our crude oil pipelines are primarily dependent upon the volume of crude oil transported (or capacity reserved) and the associated fees we charge for such transportation services.  Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental regulation of our liquids pipelines.



The following table presents selected information regarding our crude oil pipelines and related operations at February 1, 2023:

   
Operational
 
     
Storage
Pipeline
   
Ownership
Capacity
Length
Description of Asset
Location(s)
Interest
(MMBbls) (2)
(Miles)
Midland-to-ECHO System:
       
   Midland-to-ECHO 1 Pipeline
Texas
    80.0% (3)
3.7
418
   Midland-to-ECHO 2 Pipeline
Texas
  100.0%
444
   Midland-to-ECHO 3 Pipeline
Texas
    29.0% (4)
521
   Total Midland-to-ECHO System
   
3.7
1,383
Seaway Pipeline (1)
Texas, Oklahoma
    50.0% (5)
9.7
1,273
West Texas System (1)
Texas, New Mexico
  100.0%
1.4
1,044
Basin Pipeline (1)
Texas, New Mexico, Oklahoma
    13.0% (6)
6.0
601
EFS Midstream System
Texas
  100.0%
0.3
500
South Texas Crude Oil Pipeline System
Texas
  100.0%
5.8
490
Eagle Ford Crude Oil Pipeline System
Texas
    50.0% (7)
4.5
390
   Total
   
31.4
5,681

(1)
Transportation services provided by these liquids pipelines are regulated, in whole or part, by federal governmental agencies.
(2)
Operational storage capacity amounts presented on a gross basis.
(3)
The Midland-to-Sealy section of the Midland-to-ECHO 1 Pipeline is owned by Whitethorn Pipeline Company LLC, in which we own an 80% consolidated interest.
(4)
We proportionately consolidate our 29% undivided interest in the Midland-to-Webster pipeline, which we refer to as the Midland-to-ECHO 3 Pipeline.
(5)
Our 50% ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Holdings LLC (“Seaway”).
(6)
We proportionately consolidate our 13% undivided interest in the Basin Pipeline.
(7)
Our 50% ownership interest in the Eagle Ford Crude Oil Pipeline System is held indirectly through our equity method investment in Eagle Ford Pipeline LLC.

The maximum number of barrels per day that our crude oil pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the grades of crude oil being transported).  As a result, we measure the utilization rates of our crude oil pipelines in terms of net throughput, which is based on our ownership interest.  In the aggregate, net throughput volumes for these pipelines were 2,222 MBPD, 2,088 MBPD and 2,166 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

We operate our crude oil pipelines with the exception of the Basin Pipeline, Eagle Ford Crude Oil Pipeline System and Midland-to-ECHO 3 Pipeline. The following information describes our principal crude oil pipelines:

The Midland-to-ECHO System supports Permian Basin crude oil production by providing producers and other shippers with transportation solutions that are both cost-efficient and operationally flexible.  After aggregating crude at our Midland terminal, the system has the capability to transport multiple grades of crude oil, including West Texas Intermediate (“WTI”), WTI light sweet crude oil (“West Texas Light”), West Texas Sour, and condensate, to our Enterprise Crude Houston (“ECHO”) storage terminal (using batched shipments to safeguard crude quality) for further delivery to markets along the Gulf Coast.  Using the ECHO terminal, shippers on the Midland-to-ECHO System have access to every refinery in Houston, Texas City, Beaumont and Port Arthur, Texas, as well as our crude oil export terminal facilities.

The Midland-to-ECHO 1 Pipeline originates at our Midland terminal and extends 418 miles to our Sealy storage terminal.  Volumes arriving at Sealy are then transported to our ECHO terminal using the Rancho II pipeline, which is a component of our South Texas Crude Oil Pipeline System. The Midland-to-ECHO 1 Pipeline has an approximate maximum transportation capacity of up to 620 MBPD, depending on certain operational variables.

The Midland-to-ECHO 2 Pipeline originates at our Midland terminal and extends 444 miles to our Sealy terminal, with crude oil volumes arriving at Sealy transported to our ECHO terminal using the Rancho II pipeline.  The Midland-to-ECHO 2 Pipeline was created by converting the Midland-to-Sealy segment of one of our two Seminole NGL pipelines from NGL service to crude oil service.  We retain the flexibility to convert this pipeline back to NGL service should future market conditions support the need for additional NGL transportation capacity out of the Permian Basin. The Midland-to-ECHO 2 Pipeline has an approximate maximum transportation capacity of up to 225 MBPD, depending on certain operational variables.

The Midland-to-ECHO 3 Pipeline is comprised of a 36-inch pipeline extending from Midland, Texas to our ECHO terminal, and further from ECHO to a third-party terminal in Webster, Texas (collectively, the “Midland-to-Webster pipeline”).  The maximum transportation capacity on the Midland-to-Webster pipeline is approximately 450 MBPD.

The Seaway Pipeline connects the Cushing, Oklahoma crude oil hub with markets in southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. The Cushing hub is an industry trading hub and price settlement point for WTI crude oil on the New York Mercantile Exchange (“NYMEX”).

The Longhaul System consists of two approximately 500-mile, 30-inch diameter pipelines (Seaway I and the Seaway Loop) that provide north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal located near Freeport, Texas. The aggregate transportation capacity of the Longhaul System is approximately 950 MBPD, depending on the type and mix of crude oil being transported and other variables. The Jones Creek terminal is connected by pipeline to our ECHO terminal, which enables Seaway to serve a variety of customers along the upper Texas Gulf Coast including the Beaumont/Port Arthur area.

The Freeport System consists of a marine terminal that facilitates both crude oil imports and exports, along with pipelines that transport crude oil to and from Freeport, Texas and the Jones Creek terminal.

The Texas City System consists of a marine terminal and storage tanks, various pipelines and related infrastructure used to transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park, Texas area, our ECHO terminal and locations along the Houston Ship Channel.  The Texas City System also receives production from certain offshore Gulf of Mexico developments. The intrastate pipeline transportation capacity of the Freeport System and Texas City System is approximately 480 MBPD and 800 MBPD, respectively.

Seaway’s Texas City marine terminal features two docks, a 45-foot draft, an overall length of 1,125 feet, a 200-foot beam (width) and the capacity to load crude oil at a rate of 35,000 barrels per hour.  We have used Seaway’s Texas City terminal to partially load Very Large Crude Carrier (“VLCC”) tankers, with the remaining volumes subsequently loaded on such vessels using lightering operations in the Gulf of Mexico.

The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility located in Midland, Texas.  The West Texas System, including the Loving County pipeline, is a key part of our strategic crude oil aggregation program designed to support Permian Basin producers with a transport capacity over 600 MBPD. At Midland, shippers have access to storage and terminal services, as well as connectivity to multiple transportation alternatives such as trucking and pipeline infrastructure that offer access to various downstream markets, including the Gulf Coast.

The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to the Cushing hub.

The EFS Midstream System serves producers in the Eagle Ford Shale by providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas.  The EFS Midstream System includes 500 miles of gathering pipelines, 11 central gathering plants having a combined condensate storage capacity of 0.3 MMBbls, 201 MBPD of condensate stabilization capacity and 1.0 Bcf/d of associated natural gas treating capacity.

The South Texas Crude Oil Pipeline System has the capacity to transport approximately 450 MBPD of crude oil and condensate originating in South Texas to customers in the Houston area.  This system includes storage terminal assets located at Lyssy, Milton, Marshall and Sealy, Texas.  The South Texas Crude Oil Pipeline System also includes our Rancho II pipeline, which extends 89-miles from the Sealy terminal to our ECHO terminal.  From ECHO, we have connectivity to refinery customers and our marine terminals along the Texas Gulf Coast.

The Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas.  The system, which is effectively looped and has a capacity to transport over 600 MBPD of light and medium grades of crude oil, consists of 390 miles of crude oil and condensate pipelines originating in Gardendale, Texas and extending to Corpus Christi, Texas.  The system interconnects with our South Texas Crude Oil Pipeline System in Wilson County, Texas and our Corpus Christi marine terminal.

Crude oil terminals
In addition to the operational storage capacity associated with our crude oil pipelines, we also own and operate crude oil terminals located in Houston, Midland and Beaumont, Texas and Cushing, Oklahoma that are used to store crude oil for us and our customers.  In conjunction with other aspects of our midstream network, our crude oil terminals provide Gulf Coast refiners with an integrated system featuring supply diversification, significant storage capabilities and a high capacity pipeline distribution system. Our system has access to an aggregate refining capacity of approximately 8 MMBPD.

The results of operations from crude oil terminals are primarily dependent upon the level of volumes stored and the length of time such storage occurs, including the level of firm storage capacity reserved, pumpover volumes and the fees associated with each activity.  If the terminal offers marine services, the results of operations from these activities are primarily dependent upon the level of volumes handled (loading and unloading) and the associated fees we charge for such services.

The following table presents selected information regarding our crude oil terminals at February 1, 2023:

   
Number of
Net Storage
   
Ownership
Above-Ground
Capacity
Description of Asset
Location
Interest
Tanks in Service
(MMBbls)
EHT (crude oil)
Texas
100.0%
82
23.8
ECHO (1)
Texas
100.0%
15
6.5
Midland (2)
Texas
100.0%
13
5.2
Beaumont Marine West
Texas
100.0%
12
4.2
Cushing
Oklahoma
100.0%
19
3.3
Corpus Christi
Texas
       50.0% (3)
4
0.7
   Total
   
145
43.7

(1)
Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline and three tanks owned by Seaway.
(2)
Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline.
(3)
Our 50% ownership interest in the terminal is held indirectly through our equity method investment in Eagle Ford Terminals Corpus Christi LLC.

The following information describes our principal crude oil terminals, all of which we operate with the exception of the Corpus Christi terminal.

The EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 2.0 MMBPD, or 62 MMBbls per month, of crude oil.  The crude oil terminal at EHT represents one of the largest such facilities on the Gulf Coast.  As noted previously, EHT can accommodate vessels with up to a 45-foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel.

The ECHO terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston, Texas City and Beaumont/Port Arthur areas.  Beginning in March 2022, the ECHO terminal became one of two physical delivery points for the Midland WTI American Gulf Coast futures contract (“HOU”) traded on the Intercontinental Exchange (“ICE”).  ECHO also has connections to marine terminals, including EHT, that provide access to any refinery on the U.S. Gulf Coast and international markets.

The Beaumont Marine West terminal is located on the Neches River near Beaumont, Texas.  This terminal includes three deep-water docks and one barge dock that facilitate the exporting and importing of crude oil and related products.

The Cushing terminal is located at the Cushing hub in Oklahoma and provides crude oil storage, pumpover and trade documentation services.  This terminal is one of the origination points for our Seaway Pipeline.

The Midland terminal provides crude oil storage, pumpover and trade documentation services.  The Midland terminal is the origination point for our Midland-to-ECHO pipelines.

The Corpus Christi terminal, located in Corpus Christi, Texas, is capable of loading ocean-going vessels with either crude oil or condensate.  The terminal includes one deep-water ship dock and serves Eagle Ford Shale and Permian Basin producers through a connection with our Eagle Ford Crude Oil Pipeline System.


Sea Port Oil Terminal.  In January 2019, we filed our application for regulatory permitting of our Sea Port Oil Terminal (“SPOT”) in the Gulf of Mexico with the Department of Transportation’s Maritime Administration.  SPOT would consist of proposed onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Texas coast in approximately 115 feet of water.  SPOT is designed to load VLCCs and other crude oil tankers at rates of approximately 85,000 barrels per hour.  The platform would be connected to an onshore storage facility with approximately 4.8 MMBbls of capacity in Brazoria County, Texas, by two 36-inch, bi-directional pipelines.  The SPOT project includes state-of-the-art pipeline control, vapor recovery and leak detection systems that are designed to minimize emissions.  SPOT would provide customers with an integrated export solution that leverages our extensive supply, storage and distribution network along the Gulf Coast.

In November 2022, we received a favorable Record of Decision (“ROD”) from the Department of Transportation’s Maritime Administration in accordance with the provisions of the Deepwater Port Act of 1974.  The receipt of the ROD is a significant milestone in the process to obtain a license for SPOT under the Deepwater Port Act.  Remaining conditions that we must address and satisfy to obtain approval for the license issuance include routine construction, operating and decommissioning guarantees, submission of public outreach, wetland restoration and volatile organic compound (“VOC”) monitoring plans, and other state approvals.  We expect to satisfy these remaining conditions in 2023; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.

We continue to commercialize this project in order to support a final investment decision, which is subject to the execution of long-term customer contracts and receiving a license to construct and operate the facility.

Crude oil marketing activities
Our crude oil marketing activities generate revenues from the sale and delivery of crude oil and condensate purchased either directly from producers or from others on the open market.  The results of operations from our crude oil marketing activities are primarily dependent upon the difference, or spread, between crude oil and condensate sales prices and the associated purchase and other costs, including those costs attributable to the use of our assets.  In general, sales prices referenced in the underlying contracts are market-based and include pricing differentials for factors such as delivery location or crude oil quality.  We use derivative instruments to mitigate our exposure to commodity price risks associated with our crude oil marketing activities.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Our Crude Oil Pipelines & Services segment also includes a fleet of approximately 245 tractor-trailer tank trucks, the majority of which we own and operate, that are used to transport crude oil.

Natural Gas Pipelines & Services

This business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas.  This segment also includes our natural gas marketing activities.

Natural gas pipelines and related storage assets
Our natural gas gathering pipelines gather, treat and transport natural gas from production developments to regional natural gas plants for further processing.  Our natural gas transmission pipelines transport natural gas from regional processing facilities to downstream electric generation plants, local gas distribution companies, industrial and municipal customers, storage facilities or other connecting pipelines.

The results of operations from our natural gas pipelines and related storage assets are primarily dependent upon the volume of natural gas gathered, treated, transported or stored, the level of firm or interruptible capacity reservations made by shippers, and the fees associated with each activity.  Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements.  See “Regulatory Matters” within this Part I, Items 1 and 2 for information regarding governmental regulation of our natural gas pipelines.


The following table presents selected information regarding our natural gas pipelines and related infrastructure at February 1, 2023:

     
Net Capacity (1)
     
Pipeline
Pipeline
Natural Gas
Usable
   
Ownership
Length
Capacity
Treating
Storage
Description of Asset
Location(s)
Interest
(Miles)
(MMcf/d)
(MMcf/d)
(Bcf)
Texas Intrastate System  (2)
Texas
 Various (5)
6,770
7,328
12.9
Acadian Gas System (2)
Louisiana
 100.0% (6)
1,392
4,400
1.3
Jonah Gathering System
Wyoming
 100.0%
778
2,360
Piceance Basin Gathering System
Colorado
 100.0%
191
1,800
Delaware Basin Gathering System
Texas, New Mexico
 100.0%
1,763
1,575
150
White River Hub (3)
Colorado
   50.0%  (7)
10
1,500
BTA Gathering System (4)
Texas
 100.0%  (8)
801
1,420
240
Midland Basin Gathering System
Texas
 100.0%
1,782
1,305
Haynesville Gathering System
Louisiana, Texas
 100.0%
380
1,300
810
San Juan Gathering System
New Mexico, Colorado
 100.0%
5,594
1,200
Indian Springs Gathering System (4)
Texas
   80.0%  (9)
145
160
Delmita Gathering System
Texas
 100.0%
203
145
South Texas Gathering System
Texas
 100.0%
517
143
320
Old Ocean Pipeline
Texas
   50.0% (10)
240
80
Big Thicket Gathering System (4)
Texas
 100.0%
249
60
Central Treating Facility
Colorado
 100.0%
200
   Total
   
20,815
24,776
1,720
14.2

(1)
Net capacity amounts are based on our ownership interest or contractual right-of-use.
(2)
Transportation services provided by these pipeline systems, in whole or part, are regulated by both federal and state governmental agencies.
(3)
Services provided by the White River Hub are regulated by federal governmental agencies.
(4)
Transportation services provided by these systems are regulated in part by state governmental agencies.
(5)
We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,471 miles of the Texas Intrastate System.  The Texas Intrastate System also includes our Wilson natural gas storage facility, which consists of a network of leased and owned underground salt dome storage caverns located in Wharton County, Texas with an aggregate 12.9 Bcf of usable storage capacity.  Four of these caverns, comprising 6.9 Bcf of usable capacity, are held under an operating lease.  The remainder of our Texas Intrastate System is wholly owned.
(6)
The Acadian Gas System includes a leased 1.3 Bcf underground salt dome natural gas storage cavern located at Napoleonville, Louisiana.
(7)
Our 50% ownership interest in White River Hub is held indirectly through our equity method investment in White River Hub, LLC.
(8)
This system includes approximately 56 miles of leased pipelines.
(9)
We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System.
(10)
Our 50% ownership interest in the Old Ocean Pipeline is held indirectly through our equity method investment in Old Ocean Pipeline, LLC.

On a weighted-average basis, overall utilization rates for our natural gas pipelines were approximately 65.0%, 60.4% and 57.2% during the years ended December 31, 2022, 2021 and 2020, respectively.  These utilization rates represent actual natural gas volumes delivered as a percentage of our nominal delivery capacity and do not reflect firm capacity reservation agreements where capacity fees are earned whether or not the shipper actually utilizes such capacity.

We operate our natural gas pipelines and storage facilities with the exception of the White River Hub, Old Ocean Pipeline and certain segments of the Texas Intrastate System.  The following information describes our principal natural gas pipelines:

The Texas Intrastate System is comprised of the 6,161-mile Enterprise Texas pipeline system and the 609-mile Channel pipeline system. The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas including the Permian Basin and Eagle Ford and Barnett Shales for delivery to local gas distribution companies, electric utility plants and industrial and municipal consumers. The system is also connected to regional natural gas processing facilities and other intrastate and interstate pipelines.  The Texas Intrastate System serves a number of commercial markets in Texas, including Corpus Christi, San Antonio/Austin, Beaumont/Orange and Houston, including the Houston Ship Channel industrial market.

The Acadian Gas System transports, stores and markets natural gas in Louisiana.  The Acadian Gas System is comprised of the 582-mile Cypress pipeline, 424-mile Acadian pipeline, 275-mile Haynesville Extension pipeline, 83-mile Gillis Lateral pipeline and 28-mile Enterprise Pelican pipeline.  The Acadian Gas System links natural gas supplies from Louisiana (e.g., from the Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric utility plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor.  Additionally, the Acadian Gas System delivers natural gas production from the Haynesville Shale to the liquefied natural gas (“LNG”) markets in South Louisiana via the Gillis Lateral pipeline.

In April 2022, we announced plans for an additional 400 MMcf/d expansion of our Acadian Gas System. The expansion is expected to be completed in the second quarter of 2023.

The Jonah Gathering System is located in the Greater Green River Basin of southwest Wyoming.  This system gathers natural gas from the Jonah and Pinedale supply fields for delivery to regional natural gas processing facilities, including our Pioneer facility.

The Piceance Basin Gathering System gathers natural gas produced from the Piceance Basin in northwestern Colorado to our Meeker natural gas processing facility.

The Midland Basin Gathering System, which is located in West Texas, gathers natural gas from the Midland Basin for delivery to our Midland Basin processing facility.  We acquired this system, along with our Midland Basin processing facility, as part of our acquisition of Navitas Midstream in February 2022. See Part II, Item 7 of this annual report for additional information regarding this acquisition.

The Delaware Basin Gathering System is comprised of the 1,124-mile Carlsbad pipeline system, the 582-mile Waha pipeline system, the 34-mile Orla pipeline system and the 23-mile Mentone pipeline system. The Delaware Basin Gathering System gathers natural gas from the Delaware Basin for delivery to regional natural gas processing facilities, including our Delaware Basin natural gas processing facility, and delivers residue and treated natural gas into our Texas Intrastate System and third-party pipelines.

The White River Hub is a natural gas hub facility serving producers in the Piceance Basin.  The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas.

The BTA Gathering System, which is located in East Texas, gathers and treats natural gas from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.  This system includes our Fairplay Gathering System.

The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas for delivery to regional markets, including (through an interconnect with the Haynesville Extension pipeline) markets served by our Acadian Gas System.

The San Juan Gathering System gathers and treats natural gas produced from the San Juan Basin in northern New Mexico and southern Colorado and delivers the natural gas either directly into interstate pipelines or to regional natural gas plants, including our Chaco facility, for processing prior to being transported on interstate pipelines.

The Indian Springs Gathering System, along with the Big Thicket Gathering System, gather natural gas from the Woodbine, Wilcox and Yegua production areas in East Texas.

The Delmita Gathering System gathers natural gas from the Frio-Vicksburg formation in South Texas for delivery to our South Texas natural gas processing facilities.

The South Texas Gathering System gathers natural gas from the Olmos and Wilcox formations for delivery to our South Texas natural gas processing facilities.

The Old Ocean Pipeline transports natural gas from an injection point on our Texas Intrastate System near Maypearl, Texas for delivery to a pipeline interconnect at Sweeny, Texas.  A third party serves as operator of the pipeline, which has a gross natural gas transportation capacity of 160 MMcf/d.

The Central Treating Facility is located in Rio Blanco County, Colorado and serves producers in the Piceance Basin.  Natural gas delivered to the treating facility is treated to remove impurities and transported to our Meeker gas plant for further processing.


Natural gas marketing activities
Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased from producers, regional natural gas processing facilities and on the open market.  Our natural gas marketing customers include local gas distribution companies and electric utility plants. The results of operations from our natural gas marketing activities are primarily dependent upon the difference, or spread, between natural gas sales prices and the associated purchase and other costs, including those costs attributable to the use of our assets.  In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location.

We are exposed to commodity price risk to the extent that we take title to natural gas volumes in connection with our natural gas marketing activities and certain intrastate natural gas transportation contracts.  In addition, we purchase and resell natural gas for certain producers that use our San Juan, Piceance, Midland Basin, Delaware Basin and Jonah Gathering Systems and certain segments of our Acadian Gas and Texas Intrastate Systems.  Also, several of our natural gas gathering systems, while not providing marketing services, have some exposure to risks related to fluctuations in commodity prices through transportation arrangements with shippers.  For example, nearly all of the transportation revenues generated by our San Juan Gathering System are based on a percentage of a regional natural gas price index.  This index may fluctuate based on a variety of factors, including changes in natural gas supply and consumer demand.  We attempt to mitigate these price risks through the use of commodity derivative instruments.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Petrochemical & Refined Products Services

This business segment includes our:

propylene production facilities, which include propylene fractionation units and a PDH facility, and related pipelines and marketing activities;

butane isomerization complex and related deisobutanizer (“DIB”) operations;

octane enhancement, iBDH and HPIB production facilities;

refined products pipelines, terminals and related marketing activities;

an ethylene export terminal and related operations; and

marine transportation business.

Propylene production facilities and related operations
Our propylene production facilities and related operations include propylene fractionation (or splitter) units, a PDH facility, propylene pipelines, propylene export assets and related petrochemical marketing activities.

Propylene production and related marketing activities.  Propylene is a key feedstock used by the petrochemical industry.  There are three grades of propylene: polymer grade propylene (“PGP”), with a minimum purity of 99.5%; chemical grade propylene (“CGP”), with a minimum purity of approximately 93-94%; and refinery grade propylene (“RGP”), with a purity of approximately 70%.  Propylene fractionation units separate RGP, which is a mixture of propane and propylene, into either PGP or CGP.  Our PDH facility produces PGP using propane feedstocks.  The demand for PGP primarily relates to the manufacture of polypropylene, which has a variety of end uses including packaging film, fiber for carpets and upholstery, molded plastic parts for appliances, and automotive, houseware and medical products.  CGP is a basic petrochemical used in the manufacturing of plastics, synthetic fibers and foams.

To the extent we fractionate RGP for customers, we enter into toll processing arrangements.  In our petrochemical marketing activities, we purchase RGP on the open market for fractionation at our splitter units and sell the resulting PGP to customers at market-based prices.  The results of this marketing activity are primarily dependent upon the difference, or spread, between the sales prices of the PGP and the associated purchase and other costs, including the costs attributable to use of our propylene production assets and related infrastructure. To limit the exposure of these marketing activities to price risk, we attempt to match the timing and price of our feedstock purchases with those of the sales of end products.


Our petrochemical marketing activities also include the purchase of propane for our PDH facility to process into PGP, which is then sold to customers under long-term sales contracts (take-or-pay arrangements) that feature minimum volume commitments and contractual pricing that minimizes our commodity price risk.

The following table presents selected information regarding our propylene production facilities at February 1, 2023:

   
Net Plant
Total Plant
   
Ownership
Capacity
Capacity
Description of Asset
Location
Interest
(MBPD)
(MBPD)
Propylene fractionation facilities:
       
Chambers County (six units)
Texas
    Various   (1)
80
93
BRPC (one unit)
Louisiana
       30.0%  (2)
7
23
   Total
   
87
116
         
PDH facility:
       
PDH 1
Texas
     100.0%
25
25

(1)
We proportionately consolidate a 66.7% undivided interest in three of the propylene splitters, which have an aggregate 38 MBPD of total plant capacity.  The remaining three propylene fractionation units are wholly owned.
(2)
Our 30% ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”).

We produce PGP at our Chambers County facilities and CGP at our BRPC facility.  On a weighted-average basis, the overall utilization rate of our propylene production facilities was approximately 90.0%, 88.7% and 79.4% during the years ended December 31, 2022, 2021 and 2020, respectively.

Global demand for propylene is increasing; however, the use of lighter crude oil feedstocks by U.S. refiners and increased use of ethane by steam crackers has reduced propylene production from these traditional sources.  This has led to the development of more “on purpose” propylene production facilities such as our PDH 1 facility located in Chambers County, Texas.  This facility has the capacity to produce up to 1.65 billion pounds per year, or approximately 25 MBPD, of PGP.  At this nameplate production rate, the facility upgrades approximately 35 MBPD of propane as feedstock. The PDH 1 facility is integrated with our legacy Chambers County propylene fractionation units, which provides us with operational reliability and flexibility for both the PDH facility and the fractionation units. The construction of PDH 1 was underwritten by long-term, fee-based contracts that feature minimum volume commitments.

In November 2022, we reached a settlement related to legal proceedings involving the former general contractor for PDH 1.  For additional information regarding this litigation, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

PDH 2.  In September 2019, we announced the execution of long-term, fee-based contracts with affiliates of LyondellBasell Industries N.V. that support construction of our second PDH facility (referred to as “PDH 2”).  In June 2020, we executed additional long-term PGP sales agreements with Marubeni Corporation in support of PDH 2.  Like PDH 1, PDH 2 is expected to have the capacity to upgrade up to 35 MBPD of propane and produce up to 1.65 billion pounds per year of PGP.  PDH 2 is also located in Chambers County, Texas and is scheduled to begin service in the second quarter of 2023.  Once PDH 2 is placed into service and integrated with PDH 1 and our other propylene production facilities, we will have the capability to produce 11 billion pounds of propylene per year.



Propylene pipelines.  The results of operations from our petrochemical pipelines are primarily dependent upon the volume of products transported and the associated fees we charge for such transportation services.  The following table presents selected information regarding our propylene pipelines at February 1, 2023:

 
Ownership
Length
Description of Asset
Location(s)
Interest
(Miles)
Texas RGP Gathering System
Texas
  100.0%
708
Lou-Tex Propylene Pipeline
Texas, Louisiana
  100.0%
267
North Dean Pipeline System
Texas
  100.0%
181
Propylene Splitter PGP Distribution System
Texas
  100.0%
150
Taurus Pipeline
Texas
    70.0%  (1)
115
Louisiana RGP Gathering System
Louisiana
  100.0%
63
Lake Charles PGP Pipeline
Texas, Louisiana
    50.0%  (2)
27
Sabine Pipeline
Texas, Louisiana
  100.0%
24
La Porte PGP Pipeline
Texas
    80.0%  (3)
20
Total
   
1,555

(1)
We own a 70% consolidated interest in the Taurus Pipeline through our majority owned subsidiary Steor LLC.
(2)
We proportionately consolidate our 50% undivided interest in the Lake Charles PGP Pipeline.
(3)
We own an 80% consolidated interest in the La Porte PGP Pipeline through our majority owned subsidiaries, La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.

The maximum number of barrels per day that our petrochemical pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported).  As a result, we measure the utilization rates of our petrochemical pipelines in terms of net throughput, which is based on our ownership interest.  Total net throughput volumes were 163 MBPD, 152 MBPD and 140 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

With the exception of the Lake Charles PGP Pipeline in Louisiana, we operate all of our propylene production assets and related pipelines.

Propylene export assets.  Our EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 3,000 barrels per hour, or 72 MBPD, of semi-refrigerated propylene.

Isomerization and related operations
We own and operate three isomerization units located in Chambers County, Texas having an aggregate processing capacity of 116 MBPD that comprise the largest commercial isomerization facility in the U.S.  We also own and operate an 83-mile pipeline system used to transport high-purity isobutane from Chambers County, Texas to Port Neches, Texas and to Channelview, Texas.

The demand for commercial isomerization services depends upon the energy industry’s requirements for isobutane and high-purity isobutane in excess of the isobutane produced through the process of NGL fractionation and refinery operations.  Isomerization units convert normal butane feedstock into mixed butane, which is a stream of isobutane and normal butane.  DIB units, of which we own and operate ten located at our Chambers County complex, then separate the isobutane from the normal butane.  Any remaining unconverted (or residual) normal butane generated by the DIB process is then recirculated through the isomerization process until it has been converted into varying grades of isobutane, including high-purity isobutane.  The primary uses of isobutane are for the production of propylene oxide, isooctane, isobutylene and alkylate for motor gasoline. We also use certain of our DIB units to fractionate mixed butanes originating from NGL fractionation activities, imports and other sources into isobutane and normal butane.  The operating flexibility provided by our multiple standalone DIBs enables us to capture market opportunities resulting from fluctuations in demand and prices for different types of butanes.

The results of operations from our isomerization business are generally dependent on the volume of normal and mixed butanes processed and the level of toll processing fees charged to customers.

Our isomerization assets provide processing services to meet the needs of third-party customers and our other businesses, including our NGL marketing activities and octane enhancement production facility. On a weighted-average basis, the utilization rates of our isomerization facility were approximately 93.1%, 73.3% and 82.8% during the years ended December 31, 2022, 2021 and 2020, respectively.

Octane enhancement and related operations
We own and operate an octane enhancement production facility located in Chambers County, Texas that is designed to produce isobutylene and either isooctane or methyl tertiary butyl ether (“MTBE”).  The products produced by this facility are used by refiners to increase octane values in reformulated motor gasoline blends.  The high-purity isobutane feedstocks consumed in the production of these products are supplied by our isomerization units.

We sell our octane enhancement products at market-based prices.  We attempt to mitigate the price risk associated with these products by entering into commodity derivative instruments.  To the extent that we produce MTBE, it is sold exclusively into the export market.  We measure the utilization of our octane enhancement facility in terms of its combined isooctane, isobutylene and MTBE production volumes, which averaged 26 MBPD, 14 MBPD and 15 MBPD during the years ended December 31, 2022, 2021 and 2020, respectively.

We also own and operate a facility located on the Houston Ship Channel that produces up to 4 MBPD of HPIB and includes an associated storage facility with 0.6 MMBbls of related product storage capacity.  The primary feedstock for this plant, an isobutane/isobutylene mix, is produced by our octane enhancement and iBDH facilities.  HPIB is used in the production of polyisobutylene, which is used in the manufacture of lubricants and rubber.  In general, we sell HPIB at market-based prices with a cost-based floor.  On a weighted-average basis, utilization rates for this facility were 106.6%, 91.7% and 97.6% for the years ended December 31, 2022, 2021 and 2020, respectively.

The results of operations from our octane enhancement and HPIB facilities are generally dependent on the level of production volumes and the difference, or spread, between the sales prices of the products and the associated feedstock purchase costs and other operating expenses.

Isobutane Dehydrogenation Unit. We own and operate an iBDH facility located in Chambers County, Texas that is capable of processing approximately 25 MBPD of butane into nearly 1 billion pounds per year of isobutylene.  Production from the iBDH plant enables us to optimize our MTBE and high purity isobutylene assets and meet growing market demand for isobutylene.

Steam crackers and refineries have historically been the major source of propane and butane olefins for downstream use; however, with the increased use of light-end feedstocks such as ethane, the need for “on purpose” olefins production has increased.  Like our PDH facility, the iBDH plant helps meet market demand where traditional supplies have been reduced.  The iBDH plant increases our production of high purity and low purity isobutylene, both of which are used as feedstocks to manufacture lubricants, rubber products and fuel additives.

Refined products services
Our refined products services business includes refined products pipelines, terminals and associated marketing activities.

Refined products pipelines.  We own and operate the TE Products Pipeline, which is a 3,041-mile pipeline system comprised of 2,923 miles of regulated interstate pipelines and 118 miles of unregulated intrastate Texas pipelines.  The system primarily transports refined products from the upper Texas Gulf Coast to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to Chicago, Illinois; Lima, Ohio; Selkirk, New York; and a location near Philadelphia, Pennsylvania.  East of Seymour, Indiana, the TE Products Pipeline is primarily dedicated to NGL transportation service. The refined products transported by the TE Products Pipeline are produced by refineries and include motor gasoline and distillates.  

The results of operations for this pipeline system are dependent upon the volume of products transported and the level of fees charged to shippers.  The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC. See “Regulatory Matters” within this Part I, Items 1 and 2 discussion for information regarding governmental regulation of our liquids pipelines, including tariffs charged for transportation services.



The maximum number of barrels per day that our TE Products Pipeline can transport depends on the operating balance achieved at a given point in time between various segments of the system (e.g., demand levels at each delivery point and the mix of products being transported).  As a result, we measure the utilization rate of this pipeline in terms of throughput.  Aggregate throughput volumes by product type for the TE Products Pipeline were as follows for the years indicated:

 
For the Year Ended December 31,
 
   
2022
   
2021
   
2020
 
Refined products transportation (MBPD)
   
447
     
464
     
419
 
Petrochemical transportation (MBPD)
   
     
170
     
156
 
NGL transportation (MBPD)
   
56
     
52
     
55
 

The TE Products Pipeline system includes five non-regulated refined products truck terminals and 20.9 MMBbls of aggregate storage capacity.

In April 2022, we announced plans for our Texas Western Products System, created by repurposing a portion of our Mid-America Pipeline System’s Rocky Mountain segment and adding westbound service to our Chaparral Pipeline business to transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah.  The system is expected to be completed in phases beginning in the fourth quarter of 2023.

Refined products marine terminals.  We own and operate marine terminals located on the Neches River near Beaumont, Texas that handle refined products along with crude oil.  Our Beaumont facilities include five deep-water ship docks, three barge docks and access to approximately 10.4 MMBbls of aggregate refined products storage capacity.

We also handle refined products at EHT on the Houston Ship Channel.  In addition to providing vessel loading and unloading services for refined products, EHT’s refined products operations include 2.4 MMBbls of aggregate storage capacity through the use of 20 above-ground storage tanks.

The results of operations from these marine terminals are primarily dependent upon the volume handled and the associated storage and other fees we charge.

Refined products marketing activities.  Our refined products marketing activities generate revenues from the sale and delivery of refined products obtained on the open market.  The results of operations from our refined products marketing activities are primarily dependent upon the difference, or spread, between product sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets.  In general, we sell our refined products at market-based prices, which may include pricing differentials for factors such as grade and delivery location.  We use derivative instruments to mitigate our exposure to commodity price risks associated with our refined products marketing activities.  For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Ethylene export terminal and related operations
Our ethylene export terminal located at our Morgan’s Point facility on the Houston Ship Channel features two docks with a combined nameplate capacity to load 1 million tons of ethylene per year and a refrigerated storage tank capable of handling 66 million pounds of ethylene.  Ethylene is the primary feedstock for a wide variety of consumer products, including cell phones and computer parts, food packaging, apparel, textiles and personal protective equipment.  We own a 50% member interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility.  In April 2022, we announced plans to expand the ethylene export capacity of our Morgan’s Point facility.  The expansion project, which will be completed in two phases, will expand our existing capacity by 50% during 2024 and to more than double our current capacity by 2025.

Our ethylene system serves as an open market storage and trading hub for the ethylene industry by incorporating storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities.  In support of our ethylene business, our Chambers County storage complex includes a high-capacity underground ethylene storage well having a storage capacity of 600 million pounds of ethylene.  The storage well is connected to our Morgan’s Point ethylene export terminal and further to Bayport, Texas through a 58-mile pipeline system.

We also operate the Baymark ethylene pipeline in South Texas, which is a leading growth area for new ethylene crackers and related facilities.  The Baymark pipeline, which is supported by long-term customer commitments, originates in Bayport and extends 92 miles to Markham, Texas.  We own a 70% consolidated interest in the Baymark pipeline through our majority owned subsidiary, Baymark Pipeline LLC.  Customers using the Baymark pipeline have pipeline access to our high-capacity ethylene storage well in Chambers County and our export terminal at Morgan’s Point.

Marine transportation
Our marine transportation business consists of 64 tow boats and 157 tank barges used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, LPG and other petroleum products on key U.S. inland and intracoastal waterway systems.  The marine transportation industry uses tow boats as power sources and tank barges for freight capacity. We operate our marine transportation assets that serve refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida, and the Tennessee-Tombigbee waterway system.  We own and operate shipyard and repair facilities located in Houma and Morgan City, Louisiana and marine fleeting facilities located in Bourg, Louisiana and Channelview, Texas.

The results of operations from our marine transportation business are generally dependent upon the level of fees charged to transport petroleum products.

Our fleet of marine vessels operated at an average utilization rate of 92.3%, 85.2% and 86.1% during the years ended December 31, 2022, 2021 and 2020, respectively.

Our marine transportation business is subject to regulation, including by the U.S. Department of Transportation (“DOT”), Department of Homeland Security, U.S. Department of Commerce and the U.S. Coast Guard (“USCG”).  For information regarding these regulations, see “Regulatory Matters – Federal Regulation of Marine Operations,” within this Part I, Items 1 and 2 discussion.

Regulatory Matters

The following information describes the principal effects of regulation on our operations, including those regulations involving safety and environmental matters and the rates we charge customers for transportation services.

Environmental, Safety and Conservation

The safe operation of our pipelines and other assets is a top priority.  We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.

Occupational Safety and Health
Certain of our facilities are subject to general industry requirements of the Federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes.  We believe we are in material compliance with OSHA and similar state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures of employees.

Certain of our facilities are also subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.  These regulations apply to any process involving certain chemicals, flammable gases or liquids at or above a specified threshold (as defined in the regulations).  In addition, we are subject to Risk Management Plan regulations of the U.S. Environmental Protection Agency (“EPA”) at certain facilities.  These regulations are intended to complement the OSHA PSM regulations.  These EPA regulations require us to develop and implement a risk management program that includes a five-year accident history report, an offsite consequence analysis process, a prevention program and an emergency response program.  We believe we are operating in material compliance with the OSHA PSM regulations and the EPA’s Risk Management Plan requirements.

The OSHA hazard communication standard, the community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations.  Certain parts of this information must be reported to federal, state and local governmental authorities and local citizens upon request.  These laws and provisions of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) require us to report spills and releases of hazardous chemicals in certain situations.



Pipeline Safety
We are subject to extensive regulation by the DOT as authorized under various provisions of Title 49 of the United States Code and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipelines and associated facilities, including breakout tanks and gas storage facilities.  These statutes require companies that own or operate pipelines and associated facilities to (i) comply with such regulations, (ii) permit access to and copying of pertinent records, (iii) file certain reports and (iv) provide information as required by the U.S. Secretary of Transportation.  The DOT regulates natural gas and hazardous liquids pipelines through its Pipeline and Hazardous Materials Safety Administration (“PHMSA”), and in many cases, enforcement authority is delegated to state agencies.  Noncompliance with these requirements can result in substantial penalties.  We believe we are in material compliance with DOT regulations.

Congress has periodically amended the pipeline safety laws to become more stringent and more broadly applicable.  Similarly, PHMSA has undertaken several actions in recent years to increase the applicability and stringency of its regulations.  Some examples of the types of subject areas governed through the pipeline safety laws, as specified in current or pending PHMSA regulations, include:  (i) complying with industry consensus standards for safety of pipeline breakout tanks and underground natural gas storage facilities; (ii) maintaining and updating gas and hazardous liquid pipeline facility inspection and maintenance plans; (iii) leak detection and repair requirements; (iv) managing the maximum pressure of a pipeline facility, depending on factors such as its design, condition, inspection history, and material; and (v) additional integrity management, inspection, and other activities in designated “High Consequence Areas” such as populated areas, unusually sensitive areas, and commercially navigable waterways.

The development and/or implementation of more stringent requirements pursuant to regulations implementing all of the requirements of the pipeline safety laws, as well as any implementation of the PHMSA rules thereunder or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, may result in us incurring significant and unanticipated expenditures to comply with such standards.  Until any proposed regulations are finalized, the impact on our operations, if any, is not known.

Environmental Matters
Our operations are subject to various environmental and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. These include, without limitation: CERCLA; the Resource Conservation and Recovery Act (“RCRA”); the Federal Clean Air Act (“CAA”); the Clean Water Act (“CWA”); the Oil Pollution Act of 1990 (“OPA”); the OSHA; the Emergency Planning and Community Right-to-Know Act; the National Historic Preservation Act; and comparable or analogous state and local laws and regulations.  Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals with respect to air emissions, water quality, wastewater discharges and solid and hazardous waste management.  Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

If a leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held liable for all resulting liabilities, including investigation, remedial and clean-up costs.  Likewise, we could be required to remove previously disposed waste products or remediate contaminated property, including situations where groundwater has been impacted.  Any or all of these developments could have a material adverse effect on our financial position, results of operations and cash flows.

We believe our operations are in material compliance with existing environmental and safety laws and regulations and that our compliance with such regulations will not have a material adverse effect on our financial position, results of operations and cash flows.  However, environmental and safety laws and regulations are subject to change.  The trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation.  New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our financial position, results of operations and cash flows.

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters.  See Part I, Item 3 of this annual report for additional information.


Air Quality
Our operations are associated with regulated, permitted emissions of air pollutants.  As a result, we are subject to the CAA and comparable state laws and regulations including state air quality implementation plans.  These laws and regulations regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and also impose various monitoring and reporting requirements.  These laws and regulations may also require that we (i) obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing levels of air emissions, (ii) obtain and strictly comply with the requirements of air permits containing various emission and operational limitations, or (iii) utilize specific emission control technologies to limit emissions.

Increasingly, environmental groups are challenging requests to receive, modify or renew permits and seeking to apply more stringent provisions on applicants.  Our failure to comply with applicable requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, including enforcement actions, and our inability to renew or secure a needed modification to an existing permit could adversely affect our operations.  We may also be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions.

Water Quality
The CWA and comparable state laws impose strict controls on the discharge of petroleum and its derivatives into regulated waters.  The CWA provides penalties for discharges of petroleum products and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances.  State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives into navigable waters or groundwater. Federal spill prevention control and countermeasure mandates require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting regulated waters.  The EPA has also adopted regulations that require us to have permits in order to discharge regulated storm water run-off.  Storm water discharge permits may also be required by certain states in which we operate and may impose monitoring and other requirements.  The CWA prohibits discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit.  We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our financial position, results of operations and cash flows.

The primary federal law for crude oil spill liability is the OPA, which addresses three principal areas of crude oil pollution: prevention, containment and clean-up, and liability.  The OPA is applicable to regulated vessels, deep-water ports, offshore production platforms and onshore facilities, including terminals, pipelines and transfer facilities.  In order to handle, store or transport crude oil above certain thresholds, onshore facilities are required to file oil spill response plans with the USCG, the DOT’s Office of Pipeline Safety (“OPS”) or the EPA, as appropriate.  Numerous states have enacted laws similar to the OPA.  Under the OPA and similar state laws, responsible parties for a regulated facility from which crude oil is discharged may be liable for remediation costs, including damage to surrounding natural resources.  Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remediation costs.

Contamination resulting from spills or releases of petroleum products is an inherent risk within the pipeline industry.  To the extent that groundwater contamination requiring remediation exists along our pipeline systems or other facilities as a result of historical operations, we believe any such contamination could be controlled or remedied; however, such costs are site specific and there is no assurance that the impact will not be material in the aggregate.

Environmental groups have instituted lawsuits regarding certain nationwide permits issued by the U.S. Army Corps of Engineers. These permits allow for streamlined permitting of pipeline projects.  If these lawsuits are successful, timelines for future pipeline construction projects could be adversely impacted.

Disposal of Hazardous and Non-Hazardous Wastes
In our normal operations, we generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal RCRA and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of solid waste.  We also utilize waste minimization and recycling processes to reduce the volumes of our solid wastes.


CERCLA, also known as “Superfund,” imposes liability, often without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment.  These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of hazardous substances found at a facility.  Under CERCLA, potentially responsible parties may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  Under enforcement provisions, the EPA and, in some instances, third parties can take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible parties.  It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.  In the course of our ordinary operations, our pipeline systems and other facilities generate wastes that may fall within CERCLA’s definition of a “hazardous substance” or be subject to CERCLA and RCRA remediation requirements.  It is possible that we could incur liability for remediation, or reimbursement of remediation costs, under CERCLA or RCRA for remediation at sites we currently own or operate, whether as a result of our or our predecessors’ operations, at sites that we previously owned or operated, or at disposal facilities previously used by us, even if such disposal was legal at the time it was undertaken.

Endangered Species
The federal Endangered Species Act, as amended, and comparable state laws, may restrict commercial or other activities that affect endangered and threatened species or their habitats.  Some of our current or future planned facilities may be located in areas that are designated as a habitat for endangered or threatened species and, if so, may limit or impose increased costs on facility construction or operation.  In addition, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

FERC Regulation – Liquids Pipelines

Certain of our NGL, refined products and crude oil pipeline systems provide interstate common carrier movements subject to regulation by the FERC under the Interstate Commerce Act (“ICA”).  Pipelines providing such movements (referred to as “interstate liquids pipelines”) include, but are not limited to, the following: ATEX, Aegis, Dixie Pipeline, TE Products Pipeline, Front Range Pipeline, Mid-America Pipeline System, Seaway Pipeline, Seminole NGL Pipeline and Texas Express Pipeline.  These pipelines are owned by legal entities whose movements are subject to FERC regulation, including periodic reporting requirements.  For example, ATEX, Aegis and the TE Products Pipeline are owned by Enterprise TE Products Pipeline Company LLC (“Enterprise TE”), which provides certain FERC-regulated movements.

The ICA prescribes that the rates we charge for transportation on these interstate liquids pipelines must be just and reasonable, and that the rules applied to our services not unduly discriminate against or confer any undue preference upon any shipper. The FERC regulations implementing the ICA further require that interstate liquids pipeline transportation rates and rules be filed with the FERC.  The ICA permits interested persons to challenge proposed new or changed rates or rules, and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months.  Upon completion of such an investigation, the FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest.  The FERC may also investigate, upon complaint or on its own motion, a carrier’s rates and related rules that are already in effect.  If the FERC concludes, after holding a hearing on such complaint, that the challenged rate or rule was not just and reasonable, it may order a carrier to change the rate or rule prospectively and pay damages (i.e., reparations) caused by the imposition of such rate or rule for a period of up to two years prior to the filing of the complaint.

The rates charged for our interstate liquids pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based primarily on the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”).  A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of changes in the pipeline’s operating costs.  The FERC indexing is subject to review and revision every five years.  On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021, and ending on June 30, 2026, at PPI plus 0.78%.  On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI minus 0.21% effective March 1, 2022 through June 30, 2026.  The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI minus 0.21% to file rate reductions effective March 1, 2022.  Enterprise, together with a number of other midstream companies, is currently contesting this index change in the U.S. Court of Appeals for the District of Columbia Circuit.  This appeal could result in a further change to the index.  As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.  Certain of our pipelines have been granted market-based rate authority by the FERC, including Seaway.

In March 2018, the FERC issued a Revised Policy Statement on the Treatment of Income Taxes (the “Revised Policy”). The Revised Policy reversed a 13-year old policy that permitted a pipeline owned by a master limited partnership (“MLP”) to recover an income tax allowance (“ITA”) in its cost-of-service rates, if it could demonstrate that the ultimate owners of the pipeline (i.e., the unitholders of the MLP) have an actual or potential income tax liability. In July 2018, the FERC, in an Order on Rehearing, decided to provide pipeline MLPs the opportunity to argue for inclusion of an ITA in cost-of-service rates on a case-by-case basis, as opposed to having no opportunity to recover an ITA. The D.C. Circuit upheld the Revised Policy and Order on Rehearing on July 31, 2020 following court challenges initiated in September 2018.

The Revised Policy and Order on Rehearing do not impact oil and liquids pipelines with market-based rate authority, or those that charge “settlement rates.”  Following issuance of the Revised Policy, the FERC now requires crude oil and liquids pipelines owned by MLPs to remove the ITA from their cost-of-service reporting in FERC Form No. 6.  In its final rule issued December 17, 2020, the FERC removed any effect of the change in ITA treatment in determining the index for rates that became effective on July 1, 2021.

Changes in the FERC’s methodologies for approving rates could adversely affect us.  In addition, challenges to our regulated rates could be filed with the FERC and future decisions by the FERC regarding our regulated rates could adversely affect our cash flows.  We believe the transportation rates currently charged by our interstate liquids pipelines are in accordance with the ICA and applicable FERC regulations.  However, we cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines.

FERC Regulation – Natural Gas Pipelines and Related Matters

Certain of our intrastate natural gas pipelines, including the Texas Intrastate System and Acadian Gas System, are subject to regulation by the FERC under the Natural Gas Policy Act of 1978 (“NGPA”), in connection with the transportation and storage services they provide pursuant to Section 311 of the NGPA.  Under Section 311, along with the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the Natural Gas Act of 1938 (“NGA”).  These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as determined by the FERC in periodic rate proceedings.

In July 2018, the FERC issued a final rule to address the impact of the Tax Cuts and Jobs Act on cost-of-service rates for jurisdictional natural gas pipelines.  The final rule primarily impacts interstate pipelines regulated under the NGA.  With respect to intrastate pipelines regulated by the FERC under the NGPA, the rule requires an intrastate pipeline with rates on file with a state regulatory agency to file with the FERC a new rate election for its interstate rates if the state rates are reduced to reflect the reduced income tax rates adopted in the Tax Cuts and Jobs Act.  As of the filing date of this annual report, we have not been required to refile the rates for our intrastate systems as a result of this rule.

We believe that the transportation rates currently charged and the services performed by our natural gas pipelines are all in accordance with the applicable requirements of the NGPA and FERC regulations.  However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our pipelines.

The resale of natural gas in interstate commerce is subject to FERC regulation.  In order to increase transparency in natural gas markets, the FERC has established rules requiring the annual reporting of data regarding natural gas sales.  The FERC has also established regulations that prohibit manipulation of energy markets.  A violation of the FERC’s regulations may subject us to civil penalties, suspension or loss of authorization to perform services or make sales of natural gas, disgorgement of unjust profits or other appropriate non-monetary remedies imposed by the FERC.  Pursuant to the Energy Policy Act of 2005, the potential civil and criminal penalties for any violation of the NGA, or any rules, regulations or orders of the FERC, were approximately $1.5 million per day per violation as of January 2023.  The Federal Trade Commission and the Commodity Futures Trading Commission (“CFTC”) have also issued rules and regulations prohibiting energy market manipulation.  We believe that our natural gas sales activities are in compliance with all applicable regulatory requirements.


State Regulation of Pipeline Transportation Services

Transportation services rendered by our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Alabama, Colorado, Illinois, Kansas, Louisiana, Minnesota, Mississippi, New Mexico, Oklahoma, Texas and Wyoming.  Although the applicable state statutes and regulations vary widely, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be reasonable and nondiscriminatory.

Federal Regulation of Marine Operations

The operation of tow boats, barges and marine equipment create obligations involving property, personnel and cargo under General Maritime Law.  These obligations create a variety of risks including, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation between U.S. departure and destination points to vessels built and registered in the U.S. and owned and manned by U.S. citizens.  As a result of this ownership requirement, we are responsible for monitoring the foreign ownership of our common units and other partnership interests.  If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.  In addition, the USCG and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.  Our marine operations are also subject to the Merchant Marine Act of 1936, which under certain conditions would allow the U.S. government to requisition our marine assets in the event of a national emergency.

Climate Change Discussion

There is considerable discussion over global warming and climate change including the environmental effects of greenhouse gas emissions and their associated consequences on global climate, oceans and ecosystems. Climate change could have a long-term impact on our operations.  For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events.  Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe.  Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system.  Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix.

In response to governmental, scientific and public concerns that emissions of certain gases, commonly referred to as greenhouse gases, including gases associated with oil and natural gas production such as carbon dioxide, methane and nitrous oxide among others, contribute to a warming of the earth’s atmosphere and other adverse environmental effects, various governmental authorities have considered or taken actions to reduce emissions of greenhouse gases.  For example, the EPA has taken action under the CAA to regulate greenhouse gas emissions.  In addition, certain states (individually or in regional cooperation), including states in which some of our facilities or operations are located, have taken or proposed measures to reduce emissions of greenhouse gases. Also, the U.S. Congress from time to time has proposed legislative measures for imposing restrictions or requiring fees or carbon taxes for the emission of greenhouse gases.  One such fee applicable to certain of our operations has been imposed by the Inflation Reduction Act of 2022, and is known as the “Methane emissions and waste reduction incentive program.”

Actions have also taken place at the international level, with the U.S. being involved.  Various policies and approaches discussed include establishing a cap on emissions, requiring efficiency measures, or providing incentives for emissions reduction, use of renewable energy, or use of replacement fuels with lower carbon content are under discussion and have and may continue to result in additional actions involving greenhouse gases.


These federal, regional and state measures generally apply to industrial sources (including facilities in the oil and gas sector) and suppliers and distributors of fuel, and could increase the operating and compliance costs of our pipelines, natural gas processing facilities, fractionation plants and other facilities, and the costs of certain sale and distribution activities.  These regulations could also adversely affect market demand and pricing for products handled by our midstream network, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources.  The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program.  While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations.

Finally, changes in regulatory policies or market preferences that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage.

Competition

NGL Pipelines & Services

Within their respective market areas, our natural gas processing facilities and related NGL marketing activities encounter competition primarily from independent processors, major integrated oil companies, and financial institutions with commodity trading platforms.  Each of our marketing competitors has varying levels of financial and personnel resources, and competition generally revolves around price, quality of customer service and proximity to customers and other market hubs.  In the markets served by our NGL pipelines, we compete with a number of intrastate and interstate pipeline companies (including those affiliated with major oil, petrochemical and natural gas companies) and barge, rail and truck fleet operations.  In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service.

Our primary competitors in the NGL and related product storage business are major integrated oil companies, chemical companies and other storage and pipeline companies.  We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections provided and operational dependability.  Our export terminal operations compete with those operated by major oil and gas and chemical companies and other midstream service providers primarily in terms of loading and offloading throughput capacity and access to related pipeline and storage infrastructure.

We compete with a number of NGL fractionators in Kansas, Louisiana, New Mexico and Texas.  Competition for such services is primarily based on the fractionation fee charged.  However, the ability of an NGL fractionator to receive a customer’s mixed NGLs and store and distribute the resulting purity NGL products is also an important competitive factor and is a function of having the necessary pipeline and storage infrastructure.

Crude Oil Pipelines & Services

Within their respective market areas, our crude oil pipelines, storage and marine terminals and related marketing activities compete with other crude oil pipeline companies, rail carriers, major integrated oil companies and their marketing affiliates, financial institutions with commodity trading platforms and independent crude oil gathering and marketing companies.  The crude oil business can be characterized by intense competition for supplies of crude oil at the wellhead.  Competition is based primarily on quality of customer service, competitive pricing and proximity to customers and market hubs.

Natural Gas Pipelines & Services

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies.  Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements.  Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies.  Our natural gas marketing activities compete primarily with other natural gas pipeline companies and their marketing affiliates as well as standalone natural gas marketing and trading firms.  Competition in the natural gas marketing business is based primarily on competitive pricing, proximity to customers and market hubs, and quality of customer service.


Petrochemical & Refined Products Services

We compete with numerous producers of PGP, which include many of the major refiners and petrochemical companies located along the Gulf Coast, in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure.  Our petrochemical marketing activities encounter competition from major integrated oil companies and various petrochemical companies that have varying levels of financial and personnel resources, and competition generally revolves around product price, quality of customer service, logistics and location.

With respect to our isomerization operations, we compete primarily with facilities located in Kansas, Louisiana and New Mexico.  Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to supporting pipeline and storage infrastructure.  We compete with other octane additive manufacturing companies primarily on the basis of price.

With respect to our TE Products Pipeline, the pipeline’s most significant competitors are third-party pipelines in the areas where it delivers products.  Competition among common carrier pipelines is based primarily on transportation fees, quality of customer service and proximity to end users. Trucks, barges and railroads competitively deliver products into some of the markets served by our TE Products Pipeline and river terminals.  The TE Products Pipeline also faces competition from rail and pipeline movements of NGLs from Canada and waterborne imports into terminals located along the upper East Coast.

Our marine transportation business competes with other inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines.  Competition within the marine transportation business is largely based on performance and price. Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business. 

For a discussion of the general risks involving competition, see “We face competition from third parties in our midstream energy businesses” under Part I, Item 1A of this annual report.

Seasonality

Although the majority of our businesses are not materially affected by seasonality, certain aspects of our operations are impacted by seasonal changes such as tropical weather events, energy demand in connection with heating and cooling requirements and for the summer driving season.  Examples include:

Our operations along the Gulf Coast, including those at our Chambers County complex, may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

Residential demand for natural gas typically peaks during the winter months in connection with heating needs and during the summer months for power generation for air conditioning. These seasonal trends affect throughput volumes on our natural gas pipelines and associated natural gas storage levels and marketing results.

Residential demand for propane typically peaks during the winter months in connection with heating needs in rural areas. These seasonal trends can affect throughput volumes on our TE Products Pipeline, Dixie Pipeline and Mid-America Pipeline System and associated terminals.

Due to increased demand for fuel additives used in the production of motor gasoline, our isomerization and octane enhancement businesses experience higher levels of demand during the summer driving season, which typically occurs in the spring and summer months.  Likewise, shipments of refined products and normal butane experience similar changes in demand due to their use in motor fuels.

Extreme temperatures and ice during the winter months can negatively impact our gas processing plants as they may experience freeze offs.  In addition, these conditions can negatively affect our trucking and inland marine operations on the upper Mississippi and Illinois rivers.


Workforce and Related Matters

Like many publicly-traded partnerships, we have no direct employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.  The culture of our workforce is one of ownership, integrity, and opportunity. We recognize the hard work and contributions of individuals in our workforce who strive to further our goals.  We promote an environment where our employees feel that working for us is more than just a job; it is a tight-knit community that looks out for one another.  We respect employees’ differences and believe everyone should be treated with fairness and respect. We value diverse ideas and perspectives, and are committed to promoting a safe and inclusive workforce.

As of February 1, 2023, there were approximately 7,300 EPCO personnel who spend all or a substantial portion of their time engaged in our business.  From a diversity perspective, approximately 14% of these personnel were female and approximately 32% of these personnel were minorities.  We believe that the diversity of our workforce compares favorably to that of related energy industries.

The health and safety of those working on our behalf is a top priority. We promote a culture in which all personnel share the same commitment to health and safety, and recognize the importance of mitigating risks.  Acting upon our commitment to safety, we engage all levels of employees and management, our Board, our contractors, and various external entities and organizations.  We strive to achieve a goal of zero incidents and injuries.  We track our safety performance by monitoring our Total Recordable Incident Rate (“TRIR”), which is an OSHA measure that generally reflects the number of recordable incidents per 100 full-time workers during a one-year period.  Our TRIR for 2022 was 0.33, which compares favorably to the average TRIR for the midstream industry over the last six years.  We strive for year-to-year improvement in our safety performance.

Title to Properties

Our real property holdings fall into two basic categories: (i) parcels that we and our unconsolidated affiliates own in fee (e.g., we own the land upon which our Chambers County complex is constructed) and (ii) parcels in which our interests and those of our unconsolidated affiliates are derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations.  The fee sites upon which our significant facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites.  We and our affiliates have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses.

Available Information

As a publicly traded partnership, we electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”).  We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto.  Occasionally, we may also file registration statements and related documents in connection with equity or debt offerings.  The SEC maintains a website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC.

We provide free electronic access to our periodic and current reports on our website, www.enterpriseproducts.com.  These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC.  You may also contact our Investor Relations department at (866) 230-0745 for paper copies of these reports free of charge.  The information found on our website is not incorporated into this annual report.


ITEM 1A.  RISK FACTORS.

Summary of Key Risk Factors

An investment in our common units or debt securities involves certain risks.  If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows, as well as our ability to maintain or increase distribution levels.  In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Relating to Our Business

Certain developments in the global oil and gas markets, including impacts of COVID-19, the Russian invasion of Ukraine and related sanctions, have had, and may continue to have, material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.

Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

Our debt level may limit our future financial and operating flexibility.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our construction of new assets is subject to operational, regulatory, environmental, political, geopolitical, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

Several of our assets have been in service for many years and require significant expenditures to maintain them.  As a result, an increase in future maintenance or repair costs or delays in completing necessary maintenance or repair activities could have a material adverse effect on our financial position, results of operations and cash flows.

The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

A natural disaster, catastrophe, terrorist attack or other extraordinary event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

A cyber-attack on our information technology (“IT”) systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

The use of derivative financial instruments could result in material financial losses by us.

Our risk management policies cannot eliminate all commodity price risks.  In addition, any noncompliance with our risk management policies could result in significant financial losses.

Federal, state or local regulatory measures (including those related to climate, environmental, health, safety and pipeline integrity matters) could have a material adverse effect on our financial position, results of operations and cash flows.

The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO.

Risks Relating to Our Partnership Structure

We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.  In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Unitholders may have a liability to repay distributions.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, which could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

A successful IRS contest of the federal income tax positions we take and certain valuation methodologies we adopt in determining a unitholder’s allocation of income, gain, loss and deductions may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS and our cash available for distribution to our unitholders might be substantially reduced.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Tax gains or losses on the disposition of our common units could be more or less than expected.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of our common units.

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.


Discussion of Key Risk Factors

The following discussion provides additional information regarding each of our key risk factors by category:  Risks Relating to Our Business, Risks Relating to Our Partnership Structure and Tax Risks to Common Unitholders.

Risks Relating to Our Business

Certain developments in the global oil and gas markets, including impacts from COVID-19, the Russian invasion of Ukraine and related sanctions, have had, and may continue to have, material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we purchase and sell and the level of services that we provide to customers, which in turn impacts our financial position, results of operations and cash flows.

The COVID-19 pandemic continues to have global effects on demand, including as a result of international COVID-19 containment measures (e.g., quarantines, travel restrictions, temporary business closures and similar protective actions), and related reduced near-term demand for hydrocarbon products.

While many countries have eased their COVID-19 containment measures and economic activity has resumed to near pre-COVID levels, emerging variants and the potential resumption of containment measures could threaten the full recovery of hydrocarbon demand.  A continuation of hydrocarbon demand recovery remains partially dependent on successful containment of the disease, the efficacy and distribution of approved vaccines on COVID-19 and its emerging variants, and proven therapeutics. Any resumed period of economic slowdown or recession, or the return to a period of depressed demand or prices for crude oil or other products that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

The Russian invasion of Ukraine and related sanctions have also significantly disrupted supply chains for crude oil, natural gas and hydrocarbon products.  While initial impacts of the war in 2022 resulted in increased European demand for U.S. natural gas and hydrocarbon products, we cannot predict the level of future demand, effects on domestic pricing, and impacts on U.S. oil and gas production.  Any economic slowdown or recession in Europe or globally, including as a result of such supply chain disruptions or sanctions, may also impact demand and depress the price for crude oil, natural gas or other products that we handle, which could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

The future impact of these current events on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of the outbreak, the related impact on overall economic activity and the potential long-term impacts on demand for crude oil and other products, all of which cannot be predicted with certainty.

Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.

The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services.  As a result, such costs may increase during periods of general business inflation, including as a result of higher commodity prices, supply chain disruptions and tight labor markets.  Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase.  While the majority of long-term contracts for our services contain index-based changes and inflation adjustments, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services.  In addition, we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines.  In periods of general price deflation, the ceiling level provided by the FERC’s PPI-based price indexing methodology could decrease, requiring us to reduce our index-based rates, even if the actual costs we incur to operate our assets increase.  As such, our revenues and operating margins are impacted by changes in price levels.  Prior to adjustments to our applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments.  Accordingly, increased costs during periods of general business inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.

Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products.  As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.  Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services.  In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies, and government regulations affecting prices and production levels.  We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil and long-term take-or-pay agreements.

Crude oil and natural gas prices have been volatile in recent years.  For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $123.70 per barrel to a low of a negative $37.63 per barrel in the three year period ended December 31, 2022.  For the period January 1, 2023 through January 31, 2023, WTI prices ranged from a high of $81.62 per barrel to a low of $72.84 per barrel.  Natural gas prices (based on Henry Hub as measured by the NYMEX) ranged from a high of $9.68 per MMBtu to a low of $1.48 per MMBtu over the three-year period ended December 31, 2022.  Henry Hub natural gas prices ranged from a high of $4.17 per MMBtu to a low of $2.68 per MMBtu from January 1, 2023 through January 31, 2023.

Generally, prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of other uncontrollable factors, such as: (i) the level of domestic production and consumer product demand; (ii) the availability of imported crude oil and natural gas and actions taken by foreign crude oil and natural gas producing nations; (iii) the availability of transportation systems with adequate capacity; (iv) the availability of competitive fuels; (v) fluctuating and seasonal demand for crude oil, natural gas, NGLs and other hydrocarbon products, including demand for NGL products by the petrochemical, refining and heating industries; (vi) the impact of conservation efforts; (vii) governmental regulation and taxation of production; (viii) reduced demand for hydrocarbons attributable to public health emergencies and (ix) prevailing economic conditions.

We are exposed to natural gas and NGL commodity price risks under certain of our natural gas processing and gathering and NGL fractionation contracts that provide for fees to be calculated based on a regional natural gas or NGL price index, or to be paid in-kind by taking title to natural gas or NGLs.  A decrease in natural gas and NGL prices can result in lower margins from these contracts, which could have a material adverse effect on our financial position, results of operations and cash flows.  Volatility in the prices of natural gas and NGLs can lead to ethane rejection, which results in a reduction in volumes available for transportation, fractionation, storage and marketing.  Volatility in these commodity prices may also have an impact on many of our customers, which in turn could have a negative impact on their ability to fulfill their obligations to us.

The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time.  To offset this natural decline, our facilities need access to production from newly discovered properties.  Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves.  These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons.  A decrease in exploration and development activities in the regions where our facilities and other energy logistic assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows.  

For a discussion regarding our current outlook on industry fundamentals for 2023, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Outlook” included under Part II, Item 7 of this annual report.

We face competition from third parties in our midstream energy businesses.

Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted.  We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets.

Our NGL, refined products and marine transportation businesses may compete with other pipelines and marine transportation companies in the areas they serve.  We also compete with railroads and third party trucking operations in certain of the areas we serve.  Competitive pressures may adversely affect our tariff rates or volumes shipped.  Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.  

The crude oil gathering and marketing business can be characterized by intense competition for supplies of crude oil at the wellhead.  A decline in domestic crude oil production could intensify this competition among gatherers and marketers.  Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with commodity trading platforms and other companies in the areas where such pipeline systems deliver crude oil.

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies.  Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements.  Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies.  Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems.  

Both we and our competitors make significant investments in new energy infrastructure to meet anticipated market demand.  The success of our projects depends on utilization of our assets.  Demand for our new projects may change during construction, and our competitors may make additional investments or redeploy assets that compete with our projects and existing assets.  If either our investments or construction by competitors in the markets we serve result in excess capacity, our facilities and assets could be underutilized, which could cause us to reduce rates for our services.  A reduction in rates may result in lower returns on our investments and, as a result, lower the value of our assets.

A significant increase in competition in the midstream energy industry, including construction of new assets or redeployment of existing assets by our competitors, could have a material adverse effect on our financial position, results of operations and cash flows.

Our debt level may limit our future financial and operating flexibility.

As of December 31, 2022, we had $25.8 billion in principal amount of consolidated senior long-term debt outstanding and $2.3 billion in principal amount of junior subordinated debt outstanding.  The amount of our future debt could have significant effects on our operations, including, among other things:

a substantial portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our common units and for capital investments;

credit rating agencies may take a negative view of the energy sector or our consolidated debt level;

covenants contained in our existing and future credit and debt agreements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

our ability to obtain additional financing, if necessary, for working capital, capital investments, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

we may be at a competitive disadvantage relative to similar companies that have less debt; and

we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

Our public debt indentures currently do not limit the amount of future indebtedness that we can incur, assume or guarantee.  Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.  For information regarding our long-term debt, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.


Our credit agreements and each of the indentures related to our public debt instruments include traditional financial covenants and other restrictions.  For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements.  A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, terminate all commitments to extend further credit.

Our ability to access capital markets to raise capital on favorable terms could be affected by our debt level, when such debt matures, and by prevailing market conditions.  Moreover, if the rating agencies were to downgrade the energy sector or our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities.  Such a development could adversely affect our ability to obtain financing for working capital, capital investments or acquisitions, or to refinance existing indebtedness.  If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities.  The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements.  Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our growth strategy contemplates the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet.  This strategy includes constructing and acquiring additional assets and businesses that enhance our ability to compete effectively and to diversify our asset portfolio, thereby providing us with more stable cash flows.  We consider and pursue potential joint ventures, acquisitions, standalone projects and other transactions that we believe may present opportunities to expand our business, increase our market position and realize operational synergies.

We will require substantial new capital to finance the future development and acquisition of assets and businesses.  For example, our capital investments for 2022 reflected $5.2 billion of cash payments for capital projects, acquisitions and other investments.  Based on information currently available, we expect our total capital investments for 2023, net of contributions from joint venture partners, to approximate $2.7 billion to $2.9 billion, which includes growth capital projects of $2.3 billion to $2.5 billion and sustaining capital expenditures of $400 million.  These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to state and federal permitting, mitigation and related requirements.  In November 2022, we received a favorable ROD from the Department of Transportation’s Maritime Administration for SPOT; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.  Any limitations on our access to capital may impair our ability to execute this growth strategy.  If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited.  We also may not be able to raise the necessary funds on satisfactory terms, if at all.  

Any sustained tightening of the credit markets may have a material adverse effect on us by, among other things, decreasing our ability to finance growth capital projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants.  In addition, the distribution yields of any new equity we may issue may be higher than historical levels, making additional equity issuances more expensive. Accordingly, increased costs of equity and debt will make returns on capital expenditures with proceeds from such capital less accretive on a per unit basis.

We also may compete with third parties in the acquisition of energy infrastructure assets that complement our existing asset base.  Increased competition for a limited pool of assets could result in our losing to other bidders more often than in the past or acquiring assets at less attractive prices.  Either occurrence could limit our ability to fully execute our growth strategy.  Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher cash distributions in the future.

Our actual construction, development and acquisition costs could materially exceed forecasted amounts.

We have announced and are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital.  These projects entail significant logistical, technological and staffing challenges.  We may not be able to complete our projects at the costs we estimated at the time of each project’s initiation or that we currently estimate.  Similarly, force majeure events such as hurricanes along the U.S. Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects. 

If capital investments materially exceed expected amounts, then our future cash flows could be reduced, which, in turn, could reduce the amount of cash we expect to have available for distribution.  In addition, a material increase in project costs could result in decreased overall profitability of the newly constructed asset once it is placed into service.

Our construction of new assets is subject to operational, regulatory, environmental, political, geopolitical, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets.  The construction of new assets involves numerous operational, regulatory, environmental, political, geopolitical, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital.  These potential risks include, among other things, the following:
 
we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel, the unavailability of or delays in obtaining necessary materials as a result of supply chain disruptions (including those caused by COVID-19 restrictions or geopolitical events, such as the Russian invasion of Ukraine), accidents, weather conditions or an inability to obtain necessary permits;

we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize;

since we are not engaged in the exploration for and development of crude oil or natural gas reserves, we may not have access to third-party estimates of reserves in an area prior to our constructing facilities in the area.  As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;

in those situations where we do rely on third-party reserve estimates in making a decision to construct assets, these estimates may prove inaccurate;

the completion or success of our construction project may depend on the completion of a third-party construction project (e.g., a downstream crude oil refinery expansion or construction of a new petrochemical facility) that we do not control and that may be subject to numerous of its own potential risks, delays and complexities; and

we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

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